In natural mineral oil deposits, mineral oil occurs in cavities of porous reservoir rocks which are closed off from the surface of the earth by impervious covering layers. In addition to mineral oil, including proportions of natural gas, a deposit further comprises water with a higher or lower salt content. The cavities may be very fine cavities, capillaries, pores or the like, for example those having a diameter of only approx. 1 μm; the formation may additionally also have regions with pores of greater diameter and/or natural fractures.
After the borehole has been sunk into the oil-bearing strata, the oil at first flows to the production boreholes owing to the natural deposit pressure, and erupts from the surface of the earth. This phase of mineral oil production is referred to by the person skilled in the art as primary production. In the case of poor deposit conditions, for example a high oil viscosity, rapidly declining deposit pressure or high flow resistances in the oil-bearing strata, eruptive production rapidly ceases. With primary production, it is possible on average to extract only 2 to 10% of the oil originally present in the deposit. In the case of higher-viscosity mineral oils, eruptive production is generally completely impossible.
In order to enhance the yield, what are known as secondary production processes are therefore used.
The most commonly used process in secondary mineral oil production is water flooding. This involves injecting water through injection boreholes into the oil-bearing strata. This artificially increases the deposit pressure and forces the oil out of the injection boreholes to the production boreholes. By means of water flooding, it is possible to substantially increase the yield level under particular conditions.
It is known that the mineral oil yield can be enhanced by the use of suitable chemicals as assistants for oil production. With the aid of these measures, the mobility of the mineral oil in the formation should be increased, such that it can be forced out of the formation more easily in the course of water flooding. This phase of mineral oil production is frequently referred to as “Tertiary Oil Production” or “Enhanced Oil Recovery” (EOR). For example, the interfacial tension σ between the mineral oil and the aqueous phase can be lowered for this purpose by the addition of suitable surfactants, thus increasing the mobility of the oil phase. This technique is also known as “surfactant flooding”. An overview of techniques for tertiary oil production can be found, for example, in the Journal of Petroleum Science and Engineering 19(1998)265-280.
A further known technique for tertiary mineral oil production is to enhance the mineral oil yield by using microorganisms, especially bacteria. This technique is known as “Microbial Enhanced Oil Recovery” (MEOR). This involves either injecting suitable microorganisms, nutrients for the microorganisms and optionally oxygen into the mineral oil formation, or promoting the growth of microorganisms already present in the mineral oil formation by injecting nutrients and optionally oxygen.
There are various known mechanisms by which bacteria can increase the mobility of mineral oil, for example by the formation of surfactants, reduction in the viscosity of the mineral oil resulting from degradation of high molecular weight hydrocarbons, formation of CO2, formation of organic acids which can attack the rock formation and hence create new flow paths, or resulting from the detachment of the mineral oil from the rock surface. Methods for MEOR and microorganisms suitable for this purpose are disclosed, for example, in U.S. Pat. Nos. 4,475,590, 4,905,761 or 6,758,270 B1.
RU 2 060 371 C1 discloses a process for producing mineral oil using microorganisms from a deposit with inhomogeneous permeability, which has at least one injection borehole and at least one production borehole. In the process described, the deposit pressure is periodically increased and lowered. In pressure increase phases, microorganisms present in the mineral oil formation are activated by injecting a nutrient solution into the mineral oil formation. Subsequently, the injection borehole is closed. The withdrawal of mineral oil or water mixtures through the production borehole reduces the pressure again.
RU 2 194 849 C1 discloses a process for extracting mineral oil using microorganisms from a deposit with inhomogeneous permeability, which has at least one injection borehole and at least one production borehole. In the process described, the deposit pressure is periodically increased and reduced. In pressure increase phases, microorganisms and nutrient solution are injected into the formation in each case through the injection and production boreholes; in pressure reduction phases, the injection borehole is closed and liquid is withdrawn from the formation through the production borehole. Preference is given to injecting mesophilic bacteria into the injection borehole, and thermophilic bacteria into the production borehole. A disadvantage of this process is the low efficiency since the production borehole does not constantly produce oil but is regularly shut down.
RU 2 204 014 C1 discloses a process for producing mineral oil, in which a nutrient solution and carbon-oxidizing bacteria are injected into a mineral oil formation, followed by a biotechnologically produced polyacrylamide together with a crosslinker.
However, other difficulties can also occur with water flooding. In the ideal case, a water front proceeding from the injection borehole should force the oil homogeneously over the entire mineral oil formation to the production borehole. In practice, a mineral oil formation, however, has regions with different levels of flow resistance. In addition to oil-saturated reservoir rocks which have fine porosity and a high flow resistance for water, there also exist regions with low flow resistance for water, for example natural or synthetic fractures or very permeable regions in the reservoir rock. Such permeable regions may also be regions from which oil has already been recovered. In the course of water flooding, the flooding water injected naturally flows principally through flow paths with low flow resistance from the injection borehole to the production borehole. The consequences of this are that the oil-saturated deposit regions with fine porosity and high flow resistance are not flooded, and that increasingly more water and less mineral oil is produced via the production borehole. In this context, the person skilled in the art refers to “watering out of production”. The effects mentioned are particularly marked in the case of heavy or viscous mineral oils. The higher the mineral oil viscosity, the more probable is rapid watering out of production.
The prior art therefore discloses measures for closing such highly permeable zones between injection boreholes and production boreholes by means of suitable measures. As a result of these, highly permeable zones with low flow resistance are blocked and the flooding water is forced to flow again through the oil-saturated, low-permeability strata. Such measures are also known as “conformance control”. An overview of measures for conformance control is given by Borling et al. “Pushing out the oil with Conformance Control” in Oilfield Review (1994), pages 44 ff.
For conformance control, it is possible to use comparatively low-viscosity formulations of particular chemical substances which can be injected easily into the formation, and the viscosity of which rises significantly only after injection into the formation under the conditions which exist in the formation. To enhance the viscosity, such formulations comprise suitable inorganic or organic, or polymeric, components. The rise in viscosity of the injected formulation can firstly occur with a simple time delay. However, there are also known formulations in which the rise in viscosity is triggered essentially by the temperature rise when the injected formulation is gradually heated to the deposit temperature in the deposit. Formulations whose viscosity rises only under formation conditions are known, for example, as “thermogels” or “delayed gelling systems”.
SU 1 654 554 A1 discloses mixtures of aluminum chloride or aluminum nitrate, urea and water, which are injected into the mineral oil formation. At the elevated temperatures in the formation, the urea is hydrolyzed to carbon dioxide and ammonia. The release of the ammonia base significantly increases the pH of the water, and results in precipitation of a highly viscous aluminum hydroxide gel, which blocks the highly permeable zones.
U.S. Pat. No. 4,889,563 discloses the use of aqueous solutions of aluminum hydroxide chloride in combination with urea or hexamethylenetetramine (urotropin) for blocking of underground mineral oil formations. Here too, the hydrolysis of urea or hexamethylenetetramine in the formation leads to an increase in the pH and the precipitation of aluminum hydroxide.
U.S. Pat. No. 4,844,168 discloses a process for blocking sections of high-temperature mineral oil formations, in which polyacrylamide and a polyvalent metal ion, for example Fe(III), Al(III), Cr(III) or Zr (IV), are injected into a mineral oil formation with a reservoir temperature of at least 60° C. Under the conditions in the formation, some of the amide groups —CONH2 are hydrolyzed to —COOH groups, and the metal ions crosslink the —COOH groups formed, such that a gel is formed with a certain time delay.
Further suitable mixtures for “Conformance Control” are disclosed, for example, by RU 2 066 743 C1, WO 2007/135617, U.S. Pat. Nos. 7,273,101 B2, 6,838,417 B2 or US 2008/0035344 A1.
Mineral oil formations frequently do not have a homogeneous temperature distribution, but rather have more or less significant temperature gradients. Such temperature gradients may be of natural origin, but they can especially be caused by measures for secondary and/or tertiary mineral oil production. In the case of water flooding, cold water is frequently injected into the formation for months or even years. This generally lowers the formation temperature to a greater or lesser degree in the region around the injection borehole. As a typical example, table 1 shows the temperature decline in the formation temperature for some deposits in northern Siberia after prolonged water flooding:
TABLE 1Deposit temperatures of different Siberian deposits S1 to S6after prolonged water flooding.FormationFormation temperaturetemperature in theDifferenceDeposit[° C.]injection region [° C.][° C.]S1904545S2723933S3783741S4783246S51015645S6854243